1. Field of the Invention
The present invention relates to rotary drag bits and their operation and, more specifically, to the design of such bits for optimum performance in the context of controlling cutter loading and depth of cut.
2. State of the Art
Rotary drag bits employing polycrystalline diamond compact (PDC) cutters have been employed for several decades. PDC cutters are typically comprised of a disc-shaped diamond "table" formed on and bonded under high pressure, high temperature conditions to a supporting substrate such as cemented tungsten carbide (WC), although other configurations are known. Bits carrying PDC cutters, which may be brazed into pockets in the bit face or blades extending from the face or mounted to studs inserted into the bit body, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Recent improvements in the hydraulic design of bits, cutter design and drilling fluid formulation have reduced prior, notable tendencies of such bits to "ball" by increasing the volume of formation material which may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the bit face.
Even in view of such improvements, however, PDC cutters still suffer from what might simply be termed "overloading" even at low weight on bit (WOB) applied to the drill string to which the bit carrying such cutters is mounted, especially if aggressive cutting structures are employed. The relationship of torque to WOB may be employed as an indicator of aggressivity for cutters, so the higher the torque to WOB ratio, the more aggressive the cutter. This problem is particularly significant in low compressive strength formations where an unduly great depth of cut (DOC) may be achieved at extremely low WOB. The problem may also be aggravated by string bounce, wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit, with consequent overloading. Moreover, operating PDC cutters at an excessively high DOC may generate more formation cuttings than can be consistently cleared from the bit face and through the junk slots by even the aforementioned improved, state-of-the-art bit hydraulics, leading to the aforementioned bit balling phenomenon.
Another, separate problem involves drilling from a zone or stratum of higher formation compressive strength to a "softer" zone of lower strength. As the bit drills into the softer formation without changing the applied WOB (or before the WOB can be changed by the directional driller), the penetration of the PDC cutters, and thus the resulting torque on the bit, increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutters. In directional drilling, such a change causes the tool face orientation of the directional (measuring while drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit and necessitating backing off from the bottom of the borehole to re-set the tool face. In addition, a downhole motor, such as the drilling fluid-driven Moineau motors commonly employed in directional drilling operations in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase, stopping the drilling operation and again necessitating backing off from the borehole bottom to re-establish drilling fluid flow and motor output.
Numerous attempts using varying approaches have been made over the years to protect the integrity of diamond cutters and their mounting structures, and to limit cutter penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutters, U.S. Pat. No. 3,709,308 discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth of cut of PDC cutters on the bit face. Other patents disclose the use of a variety of structures immediately trailing PDC cutters (with respect to the direction of bit rotation) to protect the cutters or their mounting structures: U.S. Pat. Nos. 4,889,017, 4,991,670, 5,244,039 and 5,303,785. U.S. Pat. No. 5,314,033 discloses, inter alia, the use of cooperating positive and negative or neutral backrake cutters to limit penetration of the positive rake cutters into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutters, as disclosed in U.S. Pat. Nos. 3,153,458, 4,554,986, 5,199,511 and 5,595,252.
In another context, that of so-called "anti-whirl" drilling structures, it has been asserted in U.S. Pat. No. 5,402,856 to one of the inventors herein that a bearing surface aligned with a resultant radial force generated by an anti-whirl underreamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being underreamed. See also U.S. Pat. Nos. 4,982,802, 5,010,789, 5,042,596, 5,111,892 and 5,131,478.
While some of the foregoing patents recognize the desirability to limit cutter penetration or DOC, or otherwise limit force applied to a borehole surface, the disclosed approaches are somewhat generalized in nature and fail to accommodate or implement an engineered approach to achieving a target ROP in combination with more stable, predictable bit performance.